Fracturing slurry on demand using produced water

ABSTRACT

Systems and methods presented herein generally relate to a method that includes receiving water at a centralized facility. The method also includes receiving sand from one or more sand mines at the centralized facility. The method further includes receiving one or more chemicals at the centralized facility. In addition, the method includes using processing equipment of the centralized facility to process the water, the sand, and the one or more chemicals to produce a fracturing slurry. The method also includes conveying the fracturing slurry from the centralized facility to one or more fracturing sites.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to and the benefit of U.S. ProvisionalPatent Application Ser. No. 63/033,619, entitled “Distribution ofHydraulic Fracturing Fluids,” filed Jun. 2, 2020, which is herebyincorporated by reference in its entirety for all purposes.

BACKGROUND

The present disclosure generally relates to using water at a centralizedfacility to produce fracturing slurry on-demand for delivery to one ormore fracturing wells depending on particular needs of the one or morefracturing wells.

This section is intended to introduce the reader to various aspects ofart that may be related to various aspects of the present techniques,which are described and/or claimed below. This discussion is believed tobe helpful in providing the reader with background information tofacilitate a better understanding of the various aspects of the presentdisclosure. Accordingly, it should be understood that these statementsare to be read in this light, and not as an admission of any kind.

Shale oil and shale gas are generally only economically viable in theUnited States and Canada when hydrocarbon pricing is favorable and thescale of operations allows for fixed costs to be spread across maximumactivity as variable costs are simultaneously minimized. In general,wells generally go through three planning phases (e.g., drilling,completion, and production) in the operator's decision-making process.Often, there is limited cooperation and shared knowledge across thedomains and decision-making teams within the operator's organization.For example, completions engineers are often not well interfaced withproduction teams and, therefore, it falls upon managers that are higherup in the organization to impose simple economic rationalizations likethe reuse of produced water in hydraulic fracturing upon the field. Assuch, it has been recognized that systems for improved decision-makingwith respect to produced water are desirable.

SUMMARY

A summary of certain embodiments described herein is set forth below. Itshould be understood that these aspects are presented merely to providethe reader with a brief summary of these certain embodiments and thatthese aspects are not intended to limit the scope of this disclosure.

Certain embodiments of the present disclosure include a method thatincludes receiving water at a centralized facility. The method alsoincludes receiving sand from one or more sand mines at the centralizedfacility. The method further includes receiving one or more chemicals atthe centralized facility. In addition, the method includes usingprocessing equipment of the centralized facility to process the water,the sand, and the one or more chemicals to produce a fracturing slurry.The method also includes conveying the fracturing slurry from thecentralized facility to one or more fracturing sites.

Certain embodiments of the present disclosure also include a method thatincludes receiving water at a centralized facility via one or more waterpipelines. The method also includes receiving sand from one or more sandmines at the centralized facility via one or more sand pipelines. Themethod further includes receiving one or more chemicals at thecentralized facility. In addition, the method includes using processingequipment of the centralized facility to process the water, the sand,and the one or more chemicals to produce a fracturing slurry. The methodalso includes conveying the fracturing slurry from the centralizedfacility to one or more fracturing sites via one or more fracturingslurry pipelines.

Certain embodiments of the present disclosure also include a method thatincludes receiving produced water from one or more well sites at acentralized facility via one or produced water pipelines. The methodalso includes receiving sand from one or more sand mines at thecentralized facility via one or more sand pipelines. The method furtherincludes receiving one or more chemicals at the centralized facility. Inaddition, the method includes conveying the produced water, the sand,and the chemicals from the centralized facility to one or morefracturing sites via one or more fracturing slurry pipelines. Movementof the produced water, the sand, and the chemicals through the one ormore fracturing slurry pipelines passively mixes the produced water, thesand, and the chemicals into a fracturing slurry without using activemixing equipment.

Various refinements of the features noted above may be undertaken inrelation to various aspects of the present disclosure. Further featuresmay also be incorporated in these various aspects as well. Theserefinements and additional features may exist individually or in anycombination. For instance, various features discussed below in relationto one or more of the illustrated embodiments may be incorporated intoany of the above-described aspects of the present disclosure alone or inany combination. The brief summary presented above is intended tofamiliarize the reader with certain aspects and contexts of embodimentsof the present disclosure without limitation to the claimed subjectmatter.

BRIEF DESCRIPTION OF THE DRAWINGS

Various aspects of this disclosure may be better understood upon readingthe following detailed description and upon reference to the drawings,in which:

FIG. 1 illustrates a well site having a drilling rig positioned above asubterranean formation that includes one or more oil and/or gasreservoirs;

FIG. 2 illustrates an example life cycle for produced water generated atwell sites;

FIG. 3 is a schematic diagram of a system wherein fracturing slurry ismixed onsite at fracturing sites consistent with the life cycleillustrated in FIG. 2 ;

FIG. 4 illustrates a new circular life cycle for produced watergenerated at well sites, in accordance with embodiments of the presentdisclosure;

FIG. 5 is a schematic diagram of a system consistent with the newcircular life cycle illustrated in FIG. 4 , in accordance withembodiments of the present disclosure;

FIG. 6 is a schematic diagram of various operational components of acentralized facility illustrated in FIGS. 4 and 5 , in accordance withembodiments of the present disclosure;

FIG. 7 is a schematic diagram of a sand mine that uses non-traditionalwater (e.g., produced water or other non-fresh water) in sand miningoperations, in accordance with embodiments of the present disclosure;

FIG. 8 conceptually illustrates how a dilution manifold of processingequipment of a centralized facility may dilute chemicals and sand in aproduced fracturing slurry, in accordance with embodiments of thepresent disclosure;

FIG. 9 illustrates an exemplary dilution manifold receiving a relativelyclean fluid stream into a first flow conduit and a concentrated fluidstream into a second flow conduit, in accordance with embodiments of thepresent disclosure;

FIG. 10 illustrates dewatering equipment of processing equipment of acentralized facility for dewatering a sand laden stream for densitycontrol, in accordance with embodiments of the present disclosure;

FIG. 11 illustrates a relatively long pipe that may be used to mix sand,chemicals, and/or produced water to produce the fracturing slurry, inaccordance with embodiments of the present disclosure;

FIG. 12 illustrates a consisting of a collection point (e.g., acentralized facility) where materials (e.g., sand, chemicals, and/orproduced water) are added together in desired proportions, but not mixedtogether using conventional active mixing techniques, in accordance withembodiments of the present disclosure;

FIG. 13 is a schematic diagram of a centralized facility at which afriction-reducing additive may be added to a fluid to produce afriction-reduced hydraulic fracturing slurry using a low-shear additionsystem, in accordance with embodiments of the present disclosure;

FIG. 14 illustrates an eductor configured to be gravity-fed by a solidmetering system or other conveying mechanism, in accordance withembodiments of the present disclosure;

FIG. 15 illustrates an eductor configured to pneumatically convey anddisperse air and solids into a motive fluid, in accordance withembodiments of the present disclosure;

FIG. 16 is a schematic diagram of a process control system, inaccordance with embodiments of the present disclosure;

FIG. 17 is a cross-sectional view of a pipeline that includes anexternal pipe and an internal pipe disposed concentrically within theexternal pipe for conveying friction-reduced hydraulic fracturingslurry, in accordance with embodiments of the present disclosure; and

FIG. 18 is a cross-sectional view of a pipeline that includes anexternal pipe and a plurality of internal pipes disposed within theexternal pipe for conveying friction-reduced hydraulic fracturingslurry, in accordance with embodiments of the present disclosure.

DETAILED DESCRIPTION

One or more specific embodiments of the present disclosure will bedescribed below. These described embodiments are only examples of thepresently disclosed techniques. Additionally, in an effort to provide aconcise description of these embodiments, all features of an actualimplementation may not be described in the specification. It should beappreciated that in the development of any such actual implementation,as in any engineering or design project, numerousimplementation-specific decisions must be made to achieve thedevelopers' specific goals, such as compliance with system-related andbusiness-related constraints, which may vary from one implementation toanother. Moreover, it should be appreciated that such a developmenteffort might be complex and time consuming, but would nevertheless be aroutine undertaking of design, fabrication, and manufacture for those ofordinary skill having the benefit of this disclosure.

When introducing elements of various embodiments of the presentdisclosure, the articles “a,” “an,” and “the” are intended to mean thatthere are one or more of the elements. The terms “comprising,”“including,” and “having” are intended to be inclusive and mean thatthere may be additional elements other than the listed elements.Additionally, it should be understood that references to “oneembodiment” or “an embodiment” of the present disclosure are notintended to be interpreted as excluding the existence of additionalembodiments that also incorporate the recited features.

As used herein, the terms “connect,” “connection,” “connected,” “inconnection with,” and “connecting” are used to mean “in directconnection with” or “in connection with via one or more elements”; andthe term “set” is used to mean “one element” or “more than one element.”Further, the terms “couple,” “coupling,” “coupled,” “coupled together,”and “coupled with” are used to mean “directly coupled together” or“coupled together via one or more elements.” As used herein, the terms“up” and “down,” “uphole” and “downhole”, “upper” and “lower,” “top” and“bottom,” and other like terms indicating relative positions to a givenpoint or element are utilized to more clearly describe some elements.Commonly, these terms relate to a reference point as the surface fromwhich drilling operations are initiated as being the top (e.g., upholeor upper) point and the total depth along the drilling axis being thelowest (e.g., downhole or lower) point, whether the well (e.g.,wellbore, borehole) is vertical, horizontal or slanted relative to thesurface.

As used herein, a fracture shall be understood as one or more cracks orsurfaces of breakage within rock. Fractures can enhance permeability ofrocks greatly by connecting pores together and, for that reason,fractures can be induced mechanically in some reservoirs in order toboost hydrocarbon flow. Certain fractures may also be referred to asnatural fractures to distinguish them from fractures induced as part ofa reservoir stimulation. Fractures can also be grouped into fractureclusters (or “perf clusters”) where the fractures of a given fracturecluster (perf cluster) connect to the wellbore through a singleperforated zone. As used herein, the term “fracturing” refers to theprocess and methods of breaking down a geological formation and creatinga fracture (i.e., the rock formation around a wellbore) by pumping fluidat relatively high pressures (e.g., pressure above the determinedclosure pressure of the formation) in order to increase production ratesfrom a hydrocarbon reservoir.

In addition, as used herein, the terms “real time”, “real-time”, or“substantially real time” may be used interchangeably and are intendedto described operations (e.g., computing operations) that are performedwithout any human-perceivable interruption between operations. Forexample, as used herein, data relating to the systems described hereinmay be collected, transmitted, and/or used in control computations in“substantially real time” such that data readings, data transfers,and/or data processing steps occur once every second, once every 0.1second, once every 0.01 second, or even more frequent, during operationsof the systems (e.g., while the systems are operating). In addition, asused herein, the terms “automatic” and “automated” are intended todescribe operations that are performed are caused to be performed, forexample, by a process control system (i.e., solely by the processcontrol system, without human intervention).

It is generally the case that oil and gas wells eventually produce wateralong with hydrocarbons. Both the produced water and the returnedinjected hydraulic fracturing fluid or “flowback” (e.g., usually 15-50%of the initial volume returns, typically, gradually amalgamating withformation water) are deemed oilfield wastes and are, therefore, subjectto regulatory constraints on handling and disposal. FIG. 1 illustrates awell site 10 having a drilling rig 12 positioned above a subterraneanformation 14 that includes one or more oil and/or gas reservoirs 16.During operation, a derrick and a hoisting apparatus of the drilling rig12 may raise and lower a drilling string 18 into and out of a wellbore20 of a well 22 to drill the wellbore 20 into the subterranean formation14, as well as to position downhole well tools within the wellbore 20 tofacilitate completion and production operations of the well 22. Forexample, in certain operations, a hydraulic fracturing fluid (e.g., afracturing slurry) may be introduced into the well 22 through thedrilling string 18, as illustrated by arrow 24, which may be used tocreate fractures 26 in the subterranean formation 14 to facilitateproduction of oil and/or gas resources from the well 22. As described ingreater detail herein, the produced water and the returned injectedhydraulic fracturing fluid may be returned to the surface 28 of the wellsite 10 (e.g., through the annulus between the drilling string 18 andthe wellbore 20), as illustrated by arrow 30. In certain circumstances,for every barrel of oil that is produced from a well 22, approximatelythree barrels of formation water (e.g., relatively high salt contentwater) are also produced.

Oil and gas producers quite often contract for disposal and handling ofthe produced water with a midstream specialist firm focused on waterhandling and disposal (WHD). In many instances, the produced water istreated and injected in saltwater disposal (SWD) wells. FIG. 2illustrates an example life cycle 32 for produced water generated atwell sites 10. As illustrated in FIG. 2 , water is produced along withoil and gas at one or more production wells 22. Then, each reservoirfluid (e.g., oil, gas, the produced water, the returned injectedhydraulic fracturing fluid, and so forth) may be separated using one ormore separators 34 with most of the produced oil and gas being directedinto oil and gas pipelines 36, 38, respectively, and the remainderflared via a flare stack 40 and the produced water being directed to atemporary storage facility 42 for local (e.g., at the well site 10)treatment and subsequent storage in, for example, a surface pond 44. Ingeneral, most of the produced water is re-injected into SWD wells 46with only a small portion used for fracturing purposes via injectioninto a formation 14 by one or more fracturing wells 48.

The life cycle 32 illustrated in FIG. 2 creates quite a few additionalcosts for oil and gas producers. For example, each well site 10 mustinclude onsite chemical and sand inventory equipment (e.g., storagemechanisms such as tanks, bins, hoppers, and so forth) and blendingequipment to, for example, mix the chemicals and the sand together. Inaddition, the chemicals and the sand need to be brought to the wellsites 10 via trucks. With respect to sand transportation, the sand isusually first transported from a mine to a transloading facility, wheretrucks are loaded and the sand is sent to the well sites 10. Then, thosetrucks must return to the transloading facility empty, which doubles themileage that has to be driven in each delivery. In certain regions,approximately 550 truckloads are used for every well 22 per week (e.g.,approximately 70 truckloads per day per well 22). Chemical delivery tothe well sites 10 functions very similar to sand, except that thechemicals may come from multiple transloading facilities, with each ofthe transloading facilities using different transportation methods suchas tote tanks on flat beds, transport tanks, and/or specialized tanks.

FIG. 3 is a schematic diagram of a system 50 wherein fracturing slurryis mixed onsite at fracturing sites 52 consistent with the life cycle 32illustrated in FIG. 2 . It will be appreciated that the fracturing sites52 described herein may be a subset of the well sites 10 describedherein, the only difference being that the fracturing sites 52 are wellsites that include fracturing wells 48 (and perhaps production wells22), whereas the well sites 10 include production wells 22 (and perhapsfracturing wells 48).

As illustrated in FIG. 3 , fit-for-purpose equipment is used at thefracturing sites 52 to combine water, sand, friction reducers, and otherchemicals (e.g., iron control, biocides, clay stabilizers, surfactants,and so forth) in specific ratios to produce a fracturing slurry onsiteat the fracturing sites 52. Then, the fracturing slurry is conveyed torelatively high pressure equipment to inject the fracturing slurrydownhole. As described in greater detail herein, in such embodiments,the chemicals used onsite at the fracturing sites 52 are typicallytransported via land using trucks 54 (or flat beds or any other chemicalcontainers). In addition, sand is also transported from sand mines 56using trucks 54 (e.g., airslides, sand boxes, and so forth) via sanddistribution points 58 (e.g., transloading facilities, some of whichconvert wet sand from the sand mines 56 into dry sand beforetransportation) to the fracturing sites 52. In addition, water is oftentransferred from fracturing water pits 60 and/or from fresh watersources 62 via temporary transfer lines to the fracturing sites 52, buttrucks 54 are still widely used where such infrastructure or servicesare not available.

As such, the sand is delivered to the fracturing sites 52 using trucks54, and the sand is loaded into silos or containers prior to beingdelivered to specialized units typically known as fracturing blendersusing conveyor belts, augers and/or gravity. In addition, the chemicalsare also delivered to the fracturing sites 52 using trucks 54, and fromthere to the fracturing blenders as needed. Finally, the fracturingblenders deliver the fracturing slurry to relatively high pressure pumpsthat inject the fracturing slurry into a formation. As illustrated inFIG. 3 , each of these delivery mechanisms for chemicals, sand, andwater to the fracturing sites 52 incur transportation costs as well asgenerate unwanted pollution. Furthermore, the requirement offit-for-purpose equipment to produce the fracturing slurry onsite at thefracturing sites 52 incurs even more additional costs.

With a goal of eliminating certain of these additional costs, theembodiments described herein include a new process in which fracturingslurry (e.g., prepared using sand, water, friction reducers, and/orother chemicals) is mixed at a centralized facility and delivered viapipeline or temporary transfer lines (such as transfer hoses, lay-flathoses, polymeric pipes, metallic pipes, etc.) to fracturing sites 52 asneeded. Such centralized production and delivery of fracturing slurrymay be referred to as “slurry on demand” and eliminates all of theblending equipment required at the fracturing sites 52, eliminates theassociated trucking required to transport sand and chemicals to thefracturing sites 52, eliminates certain onsite storage at the fracturingsites 52, and eliminates logistics associated with acquiring sand andchemicals for delivery to the fracturing sites 52.

For example, FIG. 4 illustrates a new circular life cycle 64 forproduced water generated at well sites 10, as described in greaterdetail herein. As illustrated in FIG. 4 , water is produced along withoil and gas at one or more production wells 22. Then, each reservoirfluid (e.g., oil, gas, the produced water, the returned injectedhydraulic fracturing fluid, and so forth) may be separated using one ormore separators 34 with most of the produced oil and gas being directedinto oil and gas pipelines 36, 38, respectively, and the remainderflared via a flare stack 40 and the produced water being directed to atemporary storage facility 42 for local (e.g., at the well site 10)treatment and subsequent storage in, for example, a surface pond 44.However, in the embodiments described herein, at least some of theproduced water may be delivered (e.g., via one or more pipelines) to acentralized facility 66 where the produced water may be reconditioned tomeet certain specifications, and be used to mix a hydraulic fracturingfluid/slurry, which may then be delivered (e.g., via one or morepipelines) to one or more fracturing wells 48, where it may be injectedinto a formation 14 for fracturing purposes.

Although depicted as being in relatively close proximity to theproduction wells 22 and the fracturing wells 48, as described in greaterdetail herein, the centralized facility 66 may in fact be at least 0.5mile away from the well sites 10 and/or the fracturing sites 52, atleast 1.0 mile away from the well sites 10 and/or the fracturing sites52, at least 2.0 miles away from the well sites 10 and/or the fracturingsites 52, at least 5.0 miles away from the well sites 10 and/or thefracturing sites 52, at least 10.0 miles away from the well sites 10and/or the fracturing sites 52, or even farther away from the well sites10 and/or the fracturing sites 52. However, again, in certainembodiments, the centralized facility 66 may instead be adjacent to (orin close proximity to, such as within 0.1 mile of) one or more of thewell sites 10 and/or the fracturing sites 52.

FIG. 5 is a schematic diagram of a system 68 (consistent with the newcircular life cycle 64 illustrated in FIG. 4 ) wherein a centralizedfacility 66 receives produced water from one or more well sites 10 viaone or more produced water pipelines 70, receives wet sand from one ormore sand mines 56 via one or more wet sand pipelines 72, and deliversfracturing slurry to one or more fracturing sites 52 (e.g., each havingone or more fracturing wells 48) via one or more fracturing slurrypipelines 74. As illustrated in FIG. 5 , and described in greater detailherein, the centralized facility 66 may include, among other things, arecycled water pit 76 (or other water storage) to store the producedwater received from the one or more well sites 10 and processingequipment (e.g., such as sand and chemical blending equipment) 78 to mixthe produced water received from the one or more well sites 10, the sandreceived from the one or more mobile sand mines 56, and chemicals storedat the centralized facility 66 into the fracturing slurry that isdelivered to the one or more fracturing sites 52.

The embodiments described herein replace the use of fresh water infracturing applications (e.g., at fracturing sites 52) with treatedproduced water (e.g., from well sites 10). As described in greaterdetail herein, in certain embodiments, the produced water may first betreated and conditioned for fracturing purposes (e.g., oil content,organic material, calcium, magnesium, Fe2, Fe3, and other minerals arebrought within desired values) at the centralized facility 66. Then, thetreated and conditioned water may be used to mix a fracturing slurry atthe centralized facility 66. Finally, the fracturing slurry may then bedistributed via the one or more fracturing slurry pipelines 74 to theone or more fracturing sites 52 where it will be used for fracturingoperations. It is noted that the fracturing slurry that arrives at theone or more fracturing sites 52 will be ready to be pumped downhole intoa formation 14, with no additional mixing needed at the one or morefracturing sites 52. Accordingly, referring to FIGS. 2 and 3 , theproducing wells 22, the separators 34, the surface pond 44, the SWDwells 46, and so forth will no longer be required at the fracturingsites 52.

Returning to FIG. 5 , in certain embodiments, wet sand (or proppant)will be transported to the centralized facility 66 via one or more wetsand pipelines 72. In certain embodiments, the sand will be mixed at aspecific range of concentrations and, if required, diluted at thecentralized facility 66 (and/or at the fracturing sites 52) to meetdifferent pump schedule requirements. As such, the embodiments describedherein eliminate the need to transport sand using trucks. As describedabove, it is estimated that approximately 550 trucks per well will beremoved from the roads. In addition to less greenhouse gases emissions,there will also be less damage to the roads and safety will be increaseddue to reduction in traffic. Furthermore, less congestion onsite willlead to a safer work environment for completions operations.

In addition, as described in greater detail herein, other additives suchas friction reducers, surfactants, clay stabilizers, and so forth, maybe handled and mixed with the fracturing slurry at the centralizedfacility 66. If needed, the concentration of these additives may beadjusted at the fracturing sites 52 to accommodate concentrationchanges. As such, the embodiments described herein reduce chemicalstorage areas at the fracturing sites 52 and allow fracturing operatorsto focus on relatively high-pressure operations, increasing safety onlocation and improving service quality at the same time.

As such, the system 68 illustrated in FIG. 5 , and described in greaterdetail herein, changes the conventional logistical chain of sand,chemicals, and water to fracturing sites including novel methods to minesand, transport sand via pipelines, control the density of thefracturing slurry, and so forth. As described in greater detail herein,the embodiments described herein also enable more efficient equipmentutilization, a more consistent and reliable fluid, sand, and chemicalblending service, and an improved environmental footprint at the same orlower costs. Furthermore, in addition to enabling sustainable life cyclemanagement for produced water, the embodiments described herein provideother environmental benefits including, but not limited to,approximately 500 ton carbon emissions reduction per well, approximately550 less trucks on the road per well due to sand sourcing, and up to5,000 less trucks on the road per well due to streamlined waterlogistics.

FIG. 6 is a schematic diagram of various operational components of thecentralized facility 66 illustrated in FIGS. 4 and 5 . As illustrated inFIG. 6 and described in greater detail herein, wet sand 80 may bereceived at the centralized facility 66 from one or more sand mines 56,for example, via one or more wet sand pipelines 72 (however, in otherembodiments, the sand may be mined adjacent to, or relatively close to,the centralized facility 66) and stored in sand storage 82 such ashoppers. In addition, chemicals 84 may be received at the centralizedfacility 66, for example, via trucks that deliver the chemicals 84, asdescribed in greater detail herein, and the chemicals 84 may be storedin chemical storage 86 such as chemical tanks or bins.

Furthermore, produced water 88 may be received at the centralizedfacility 66 from one or more well sites 10, for example, via one or moreproduced water pipelines 70 and stored in water storage 76 such as tanksor a recycled water pit. Although described primarily herein as usingproduced water 88 received from one or more well sites 10, in otherembodiments, another water source may be received and used by thecentralized facility 66 including, but not limited to, fresh water,water destined for injection via SWD wells 46, water that has beentreated for use on a fracturing fleet, water that has been treated toremove certain contaminants, brackish water, water with relatively hightotal dissolved solids (TDS), and so forth.

As described in greater detail herein, the centralized facility 66 maybe at least 0.5 mile away from the sand mines 56, the well sites 10,and/or the fracturing sites 52, at least 1.0 mile away from the sandmines 56, the well sites 10, and/or the fracturing sites 52, at least2.0 miles away from the sand mines 56, the well sites 10, and/or thefracturing sites 52, at least 5.0 miles away from the sand mines 56, thewell sites 10, and/or the fracturing sites 52, at least 10.0 miles awayfrom the sand mines 56, the well sites 10, and/or the fracturing sites52, or even farther away from the sand mines 56, the well sites 10,and/or the fracturing sites 52. However, again, in certain embodiments,the centralized facility 66 may instead be adjacent to (or in closeproximity to, such as within 0.1 mile of) one or more of the sand mines56, the well sites 10, and/or the fracturing sites 52.

As described in greater detail herein, processing equipment 78 of thecentralized facility 66 may process the sand 80, the chemicals 84, andthe produced water 88 to produce, among other things, fracturing slurry90 that may be delivered to one or more fracturing sites 52 from thecentralized facility 66, for example, via one or more fracturing slurrypipelines 74. As illustrated, in certain embodiments, a portion of theproduced fracturing slurry 90 may be stored in fracturing slurry storage92 such as slurry tanks. In addition, in certain embodiments, some ofthe water from the processing equipment 78 may be recirculated back intothe water storage 76, as described in greater detail herein.

In addition, in certain embodiments, a process control system 94 may beused to control the processing operations of the centralized facility66, as described in greater detail herein. For example, in certainembodiments, the process control system 94 may send control signals tovarious equipment (e.g., valves, pumps, and so forth) of the centralizedfacility 66 to, for example, automatically control properties(densities, chemical concentrations, flowrates, water compositions, andso forth) of the produced fracturing slurry 90 in substantially realtime to desired setpoints based on parameters of the sand 80, thechemicals 84, and the produced water 88, which may be measured byvarious sensors 96 disposed around the centralized facility 66. Inaddition, in certain embodiments, the process control system 94 mayensure that the produced water 88 is brought within fracturing waterspecifications prior to blending the produced water 88 with the sand 80and the chemicals 84 to produce the fracturing slurry 90.

In addition, in certain embodiments, the produced water 88 stored at thecentralized facility 66 may be used at the one or more sand mines 56 toaid in mining operations, as opposed to fresh water, which is typicallyused in conventional sand mines. For example, in certain embodiments,the produced water 88 may be transported to the one or more sand mines56 via one or more water supply pipelines 95. In general, the sand 80may be mined nearby an area to be serviced. From the one or more sandmines 56, the sand 80 may be transported either directly to the one ormore fracturing sites 52 or to the centralized facility 66 forprocessing. In general, the relative geographic locations of the one ormore sand mines 56 and the one or more fracturing sites 52 willdetermine the most efficient destination points.

FIG. 7 is a schematic diagram of a sand mine 56 that usesnon-traditional water (e.g., produced water 88 or other non-fresh water)in sand mining operations. As described in greater detail herein, sandmines typically use fresh water to operate the mines in a closed loopsystem with the main losses being moisture left within the sand duringprocessing. Conventional sand mines typically use fresh water since theynormally do not have access to produced water, and because of particularspecifications typically received from customers. In contrast, theembodiments described herein supply sand mines 56 (whether mobile orpermanent) with a source of water from a non-traditional source (e.g.,produced water 88 from well sites 10 or fracturing sites 52, waterintended for injection via SWD wells 46, water that is in the process ofbeing recycled, and so forth) and using the source of water in themining process. The embodiments described herein use the non-traditionalwater to wash sand 80 (e.g., stored in one or more mining hoppers 98) ina wash plant 100 and then transport the sand 80 using the water 88 to areceiving site (e.g., a fracturing site 52).

There are multiple iterations for the sand mine 56 illustrated in FIG. 7. For example, in certain embodiments, the sand mine 56 may either beclosed loop or open loop. In addition, in certain embodiments, the sandmine 56 may be a permanent installation or a mobile installation.Furthermore, in certain embodiments, the wash plant 100 may be locatedat a separate location from the sand mine 56 or the centralized facility66, and may be operated in a standalone manner, or may be operated inconjunction with a decanting pile. In addition, in certain embodiments,the mining process performed by the sand mine 56 may include washing thesand 80 using the wash plant 100, transporting the sand 80 within thesand mine 56 as a slurry (e.g., proppant), and/or transporting the sand80 directly from the sand mine 56.

In addition, although illustrated in FIG. 7 as being produced water 88(e.g., from well sites 10 or fracturing sites 52), in other embodiments,the water source used by the sand mine 56 may include water destined forinjection via SWD wells 46, water that has been treated for use on afracturing fleet, water that has been treated to remove certaincontaminants, brackish water, water with relatively high total dissolvedsolids (TDS), and so forth. In addition, although illustrated in FIG. 6as being delivered from the centralized facility 66, in otherembodiments, the produced water 88 may instead be received at the sandmine 56 directly from one or more well sites 10 or one or morefracturing sites 52 or may be received from a recycling plant. Inaddition, although illustrated in FIG. 7 as being delivered to afracturing site 52, in other embodiments, the slurry (e.g., proppant)produced at the sand mine 56 may instead be delivered to fracturingtanks, a handling facility, fracturing equipment, a decanting pile, orother locations. In addition, in certain embodiments, certain chemicalsmay be added to the slurry to aid in transportation of the slurry fromthe sand mine 56.

Returning now to FIG. 6 , as described in greater detail herein, theprocessing equipment 78 of the centralized facility 66 may includevarious subsystems that enable the operation of the centralized facility66. For example, in certain embodiments, the various subsystems of theprocessing equipment 78 may include, but are not limited to, a dilutionmanifold for diluting the chemicals 84 and the sand 80 in a producedfracturing slurry 90, equipment for dewatering a sand laden stream fordensity control, a relatively long pipe to passively mix the sand 80,chemicals 84, and produced water 88, and a low-shear addition system foradding friction-reducing additives. As will be appreciated, any and allof these subsystems may be used individually or in combination with anyand all combinations of the other subsystems. Each of these subsystemswill be described in greater detail below.

For example, FIG. 8 conceptually illustrates how a dilution manifold 102of the processing equipment 78 of the centralized facility 66 may dilutethe chemicals 84 and the sand 80 in a produced fracturing slurry 90. Asillustrated in FIG. 8 , the dilution manifold 102 is configured toautomatically proportion two different fluid streams (e.g., a relativelyclean fluid stream 104 having no, or at most trace amounts of, chemicals84 or sand 80 and a concentrated fluid stream 106 having relativelylarge amounts of chemicals 84 and/or sand 80) in order to achievespecific concentrations of certain chemicals 84 and/or sand 80 in thefracturing slurry 90 at a discharge of the dilution manifold 102.

FIG. 9 illustrates an exemplary dilution manifold 102 receiving arelatively clean fluid stream 104 into a first flow conduit 108 and aconcentrated fluid stream 106 into a second flow conduit 110. Again, therelatively clean fluid stream 104 may include no, or at most traceamounts (e.g., less than 5%, less than 3%, less than 1%, or even less)of, chemicals 84 or sand 80, whereas the concentrated fluid stream 106may include relatively large amounts (e.g., greater than 5%, greaterthan 10%, greater than 15%, greater than 20%, or even more) of chemicals84 and/or sand 80.

In certain embodiments, the dilution manifold 102 may include respectiveflowmeters 112, densitometers 114, and fluid control valves 116 in bothflow conduits 108, 110 to automatically adjust suction ratios of thefluid streams 104, 106 in order to discharge a fluid stream (e.g.,fracturing slurry 90) having desired concentrations and densities ofchemicals 84 and/or sand 80 through a discharge conduit 118 of thedilution manifold 102. In particular, although not illustrated in FIG. 9, in certain embodiments, a process control system 94 (see FIG. 6 ) mayreceive signals from the flowmeters 112 and the densitometers 114relating to flow rates and densities of the respective fluid streams104, 106, and based at least in part on the received signals, generateand send control signals to the fluid control valves 116 toautomatically adjust the blending of the fluid streams 104, 106 in orderto maintain desired fluid ratios in order to achieve the desiredconcentrations and densities of the chemicals 84 and/or sand 80 in thefluid stream (e.g., fracturing slurry 90) discharged from a dischargeconduit 118 of the dilution manifold 102. In general, the dilutionmanifold 102 uses turbulence of the fluid streams 104, 106 within thedischarge conduit 118 to homogenize the final mixture without requiringeductors, mixing chambers or tanks, impellers, or other active mixingmechanisms.

In addition, FIG. 10 illustrates dewatering equipment 120 of theprocessing equipment 78 of the centralized facility 66 for dewatering asand laden stream for density control. In general, the dewateringequipment 120 receives a first slurry 122 (e.g., fracturing slurry 90)that contains a relatively high concentration of proppant (e.g., sand80). The first slurry 122 is passed through the dewatering equipment 120to remove water (e.g., wastewater) 124 from the first slurry 122 toproduce a second slurry 126 having an increased concentration ofproppant, which may be stored in fracturing slurry storage 128 (e.g.,storage 92 illustrated in FIG. 6 ) in certain embodiments. Although notillustrated in FIG. 10 , in certain embodiments, a process controlsystem 94 (see FIG. 6 ) may control the concentration of proppant in thesecond slurry 126 to a designated setpoint by, for example, sendingcontrol signals to the dewatering equipment 120.

Then, in certain embodiments, the second slurry 126 may be mixed withwater (e.g., wastewater) 130 by blending equipment 132 that dilutes theconcentration of the second slurry 126 to produce a third slurry 134having another designated setpoint concentration of proppant, which maybe delivered to a receiving location such as a fracturing site 52. Aswith the other blending equipment described herein, in certainembodiments, the blending equipment 132 illustrated in FIG. 10 mayutilize passive blending of the second slurry 126 and the water 130.Again, although not illustrated in FIG. 10 , in certain embodiments, aprocess control system 94 (see FIG. 6 ) may control the concentration ofproppant in the third slurry 134 to another designated setpoint by, forexample, sending control signals to various valves to control respectiveflow rates of the third slurry 126 and the water 130.

In addition, as illustrated in FIG. 11 , in certain embodiments, arelatively long pipe 136 may be used to mix the sand 80, chemicals 84,and/or produced water 88 to produce the fracturing slurry 90 describedherein. As described in greater detail herein, conventional fracturingslurry delivery operations include shearing the fracturing slurry usingmechanical means such as centrifugal pumps, vortex mixers, mixing tubs,and so forth. In contrast, the embodiments described herein enablepassive mixing through the pipe 136 rather than using active mixing. Assuch, the pipe 136 achieves a homogenous fracturing slurry 90 to be usedin fracturing operations at one or more fracturing sites 52 withoutusing specialized mixing or blending equipment to blend the mixture.

As illustrated in FIG. 12 , the process consists of a collection point(e.g., the centralized facility 66 described herein) where materials(e.g., sand 80, chemicals 84, and/or produced water 88) are addedtogether in desired proportions, but not mixed together usingconventional active mixing techniques. Rather, after collection, aheterogeneous mixture of the materials is energized to be directedthrough the relatively long pipe 136 using a centrifugal pump 138. Incertain embodiments, the pipe 136 may be longer than 0.5 mile, longerthan 1.0 mile, longer than 2.0 miles, longer than 5.0 miles, longer than10.0 miles, or even longer. In certain embodiments, the mixture may beenergized multiple times along the relatively long pipe 136 to ensureproper flow rates as it travels through the pipe 136 to one or moredestination points (e.g., one or more fracturing sites 52). Relying onshear forces in the relatively long pipe 136 and the relatively longtravel time in the pipe 136, the fracturing slurry 90 reaches the one ormore destination points as a homogeneous mixture of the materials. Incertain embodiments, the mixture of materials flowing through therelatively long pipe 136 may flow at a rate of between approximately 4feet per second and approximately 16 feet per second, at a rate ofbetween approximately 6 feet per second and approximately 12 feet persecond, or at a rate of between approximately 8 feet per second andapproximately 10 feet per second.

Although described primarily herein as mixing sand 80, chemicals 84, andproduced water 88 to produce the fracturing slurry 90, in otherembodiments, different combinations of materials may be mixed using thetechniques described herein. For example, in certain embodiments, thefracturing slurry 90 may be comprised of only sand 80 and produced water88, only chemicals 84 and produced water 88, only chemicals 84 andacids, or any other conceivable combinations. In addition, in certainembodiments, the sand 80 used to produce the fracturing slurry 90 may bedry sand, moist sand, or sand disposed in liquid. In addition, incertain embodiments, the chemicals 84 used to produce the fracturingslurry 90 may be dry chemicals, liquid chemicals, or some combinationthereof.

In addition, although described primarily herein as being a centralizedfacility 66, in other embodiments, the collection point at which theproduction of the fracturing slurry 90 begins may instead be an opentank or a closed tank. In addition, in certain embodiments, the sand 80used to produce the fracturing slurry 90 may be received from a mobilesand mine 56 or a permanent sand mine 56. In addition, althoughdescribed primarily herein as being one or more fracturing sites 52, inother embodiments, the destination point to which the fracturing slurry90 is delivered may instead be a holding tank, an agitated tank, orequipment that pumps the fracturing slurry 90 downhole.

In addition, in certain embodiments, the relatively long pipe 136 thatmay be used to provide the passive mixing described herein may include atransfer hose, a lay-flat hose, polymeric pipe, metal pipe (e.g., eithertemporary or permanent), or pipe made of other materials. In addition,in certain embodiments, the relatively long pipe 136 may have aninterior surface that is textured (i.e., not smooth, but rather havingprotrusions, indentions, and so forth) to facilitate mixing of thematerials. In addition, in certain embodiments, the fracturing slurry 90may be distributed from the collection point (e.g., the centralizedfacility 66, in certain embodiments) by a centrifugal pump, a positivedisplacement pump, or any other suitable pump. Furthermore, in certainembodiments, the relatively long pipe 136 may have a plurality ofbooster pumps disposed along the length of the pipe 136 to ensure thatthe mixture is reenergized to be able to be pumped the relatively longdistance.

In general, the mechanism of proppant transport is essentially velocity,which is maximized as flow rate is maximized. The limitation on flowrate is generally governed by net treating pressure at the surface,which is affected by overburden pressure, perforation friction (e.g.,where perforating is the mechanism of contacting the reservoir from thecased well), hydrostatic weight of the fracturing slurry, tubingfriction pressure, and so forth. Friction reducers may be used as anenabling technology to reduce the tubing friction pressure term by up to80% as compared to the base fluid and/or slurry. Using friction reducerscan result in higher injection rates at the perforations, which givesmore velocity and more sand transport.

Most water-soluble polymers reduce friction; however, it has been foundthat anionic polyacrylamides are a particularly good choice forfracturing from a cost- and performance-optimization perspective.Anionic polyacrylamides require a certain level of knowledge in order tobe selected and used efficiently. However, in general, they are wellunderstood and very efficient both in terms of cost and frictionreduction performance per pound of material. In general, it is importantto match the polymer chemistry to the water's salinity, and the primarydeterminant of success is tolerance of divalent cations (e.g., Ca2+,Mg2+, Fe2+, . . . ) because of their tendency to greatly suppress thepolymer's radius of gyration in solution due to the way the concentratedcationic charges associate with anionic charges along the polymerbackbone, thus decreasing the net negative charge and occasionallycrosslinking the polymer to itself. Accordingly, as described in greaterdetail herein, in certain embodiments, sensors may be used to detectproperties of a fluid (e.g., a fracturing slurry 90), and these detectedproperties may be used to determine which polymers should be used, aswell as concentrations of the polymers.

It has also been recognized that higher molecular weight polymers aremore efficient, pound for pound, at reducing friction than lowermolecular weight polymers. The polymers are highly hygroscopic and areused extensively in water-control projects in oil and gas operations, inpulp-and-paper operations, and in water treatment operations asflocculants/clarifiers, and in solution as dry products inwater-absorbing applications such as diapers. Certain blended frictionreducer packages feature a hydrocarbon phase or vehicle that suspendseither surfactant-stabilized droplets of concentrated polymer (e.g., upto 30% of total mass) or slurried particles of dry polyacrylamide. Thepurpose of the hydrocarbon phase is to allow the highly hygroscopicpolymer to disperse in solution prior to hydration, thus avoiding theformation of relatively viscous regimes in the process train where thepolymer concentration is high enough that the local viscosity preventsthe dispersion and hydration of further polymer entering the system.

Historically, relatively high shear at the point of addition has beenused to allow preparation of uniform mixtures that are performant infracturing. However, recent improvements in dry friction reducertechnology have facilitated the addition of polymers under relativelylow-shear conditions without detrimental viscosity at appropriateconcentrations for hydraulic fracturing, as described in greater detailherein. This enables cost savings on products due to the absence of thehydrocarbon phase and the surfactants, and also in logistics by allowingtransport of dry additives rather than liquids to location. These recentimprovements have in turn led to additional cost reduction andsimplification by centralizing fluid preparation at a point where, forexample, produced water 88 is collected and stored for many operators.

As such, the embodiments described herein also generally include systemsand methods that facilitate low-shear (or even no-shear) addition offriction-reducing additives to a fluid (e.g., fracturing slurry 90) at acentralized facility 66, the conveyance of the friction-reduced fluid toa well site 10 (or a fracturing site 52), and the injection of thefriction-reduced water into a reservoir 16 to stimulate a productionwell 22. As used herein, the term “low-shear” is intended to describerelatively low levels of shear or even no shear (e.g., such as passivemixing) as compared to other conventional techniques.

FIG. 13 illustrates a low-shear addition system 140 of the processingequipment 78 of the centralized facility 66 configured to add afriction-reducing additive 142 to a fluid 144 to produce a fracturingslurry 90, which may be delivered to one or more fracturing sites 52. Incertain embodiments, the fluid 144 may be produced water 88, acombination of produced water 88 and sand 80, a combination of producedwater 88, sand 80, and chemicals 84, or any other combination of these,as described in greater detail herein. In addition, although describedprimarily herein as using produced water 88 received from one or morewell sites 10, in other embodiments, another water source may be used toproduce the fracturing slurry 90 including, but not limited to, freshwater, water destined for injection via SWD wells 46, water that hasbeen treated for use on a fracturing fleet, water that has been treatedto remove certain contaminants, brackish water, water with relativelyhigh total dissolved solids (TDS), and so forth. As described in greaterdetail herein, once the fracturing slurry 90 is produced, it may beconveyed from the centralized facility 66 to one or more fracturingsites 52, for example, via one or more fracturing slurry pipelines 74,and the fracturing slurry 90 may be injected into one or more reservoirs(e.g., using one or more fracturing pumps 146) via one or morefracturing wells 48 at the one or more fracturing sites 52 to stimulateone or more production wells 22.

In certain embodiments, the friction-reducing additive 142 may includeat least one of a polyacrylamide, a partially hydrolyzed polyacrylamide,a cross-linked polyacrylamide, a polymethacrylamide, a partiallyhydrolyzed polymethacrylamide, a cross-linked polymethacrylamide, apolyacrylic acid, a polymethacrylic acid, a polyacrylate, apolymethacrylate, a carboxymethyl cellulose, a polyvinylpyrrolidone, apolysaccharide (e.g., such as xanthan gum, welan gum, and diutan gum),or guar. In addition, in certain embodiments, the friction-reducingadditive 142 may include a co-polymer of at least one of apolyacrylamide, a partially hydrolyzed polyacrylamide, a cross-linkedpolyacrylamide, a polymethacrylamide, a partially hydrolyzedpolymethacrylamide, a cross-linked polymethacrylamide, a polyacrylicacid, a polymethacrylic acid, a polyacrylate, a polymethacrylate, acarboxymethyl cellulose, a polyvinylpyrrolidone, or a polysaccharide(e.g., such as xanthan gum, welan gum, and diutan gum).

As illustrated in FIG. 13 , in certain embodiments, one or more transferpumps 148 located at the one or more well sites 10 may be used to pumpproduced water 88 from one or more production wells 22 through one ormore produced water pipelines 70 to the centralized facility 66. Asdescribed in greater detail herein, using produced water 88 from one ormore production wells 22 to produce fracturing slurry 90 for use in theone or more fracturing wells 48 provides economic and environmentalefficiency, among other benefits. However, although illustrated in FIG.13 , and primarily described herein, as utilizing produced water 88 fromone or more production wells 22, in other embodiments, water from otherwater sources (e.g., such as those described herein), for example,located at or near the centralized facility 66 may also be used toproduce the fracturing slurry 90 described herein.

As described in greater detail herein, the low-shear addition system 140facilitates the production of friction-reduced hydraulic fracturingslurry 90 in a relatively low-shear environment as opposed toconventional systems that include relatively high-shear mixers, as wellas the use of transport units to transport fluids to well sites. Manydifferent types of low-shear addition systems 140 may be used. Forexample, eductors consist of tools into which a motive fluid isinjected, and a secondary fluid is induced to move (e.g., to agitateliquids, to mix two or more liquids intimately, to bulk transportsolids, and so forth), often by the Venturi effect of the motive fluid.In general, velocities align rapidly in eductors such that the intimatecontact is relatively low-shear but highly dispersed. Although manyvariations exist, eductors all generally follow the same principle ofoperation. Eductors are an effective and low-shear mechanism to airliftand dissolve high volumes of powdered solids in liquids (e.g., mixingpolyacrylamide polymers in water, as described in greater detailherein). In contrast, other low-shear blending systems simply sift thesolids on the liquid phase; however, this practice is only applicablefor solids that easily disperse. However, in certain embodiments,polyacrylamides may be hydrated using this mechanism if slowly added insmall quantities.

In certain embodiments, the low-shear addition system 140 may includeone or more eductors configured to add the friction-reducing additive142 to a fluid 144 to produce friction-reduced hydraulic fracturingslurry 90 in a relatively low-shear environment. FIGS. 14 and 15illustrate example eductors 150A, 150B that may be used in the low-shearaddition system 140 to disperse solids into a liquid phase, as describedherein. The eductor 150A illustrated in FIG. 14 is gravity-fed by asolid metering system or other conveying mechanism. As illustrated inFIG. 14 , the eductor 150A is configured to receive air and solids(e.g., including the friction-reducing additive 142) via an opening 152Ain the top of the eductor 150A. In certain embodiments, the gravity-fednature of the eductor 150A may be further enhanced by a vacuum 154Aproduced in the opening 152A of the eductor 150A. As also illustrated inFIG. 14 , a motive fluid 144 that has been pumped into the eductor 150A)may be introduced into the eductor 150A via a conduit 156A that includesa nozzle 158A through which the fluid 144 may flow such that thefriction-reducing additive 142 is dispersed within the fluid 144 in arelatively low-shear environment 160A within a main chamber 162A of theeductor 150A before exiting the eductor 150A as the friction-reducedhydraulic fracturing slurry 90 and, in certain embodiments, beingdelivered to one or more well sites 10 and/or one or more fracturingsites 52, for example, via one or more relatively long pipes 136, asdescribed herein.

In contrast, the eductor 150B illustrated in FIG. 15 is configured topneumatically convey and disperse air and solids (e.g., including thefriction-reducing additive 142) into a motive fluid 144. For example, asillustrated in FIG. 15 , the fluid 144 may be introduced into theeductor 150B via an opening 152B in the top of the eductor 150B. As alsoillustrated in FIG. 15 , the eductor 150B is configured to receive airand solids (e.g., including the friction-reducing additive 142) via aconduit 156B that includes a nozzle 158B (e.g., a gel gun) through whichthe air and solids may flow such that the friction-reducing additive 142is dispersed within the fluid 144 in a relatively low-shear environment160B within a main chamber 162B of the eductor 150B before exiting theeductor 150B as the friction-reduced hydraulic fracturing slurry 90 and,in certain embodiments, being delivered to one or more well sites 10and/or one or more fracturing sites 52, for example, via one or morerelatively long pipes 136, as described herein. In certain embodiments,the pneumatic nature of the eductor 150B may be further enhanced by avacuum 154B produced in the conduit 156B of the eductor 150B.

In addition, in other embodiments, the low-shear addition system 140 mayemploy other types of low-shear (or no-shear) addition mechanisms. Forexample, in certain embodiments, the low-shear addition system 140 mayemploy low-shear addition mechanisms where the friction-reducingadditive 142 is simply gravity fed, such as a gravity auger fed system,into a conduit or tank that includes the fluid 144.

Regardless of the type of low-shear addition system 140 employed, theembodiments described herein facilitate the preparation of treatmentfluid (e.g., the friction-reduced hydraulic fracturing slurry 90) forhydraulic fracturing in relatively large volumes and/or on a continuousbasis at a centralized facility 66. The centralized preparation of afriction-reduced hydraulic fracturing slurry 90 as described hereinenables operators to save costs by achieving economy of scale onproppants (e.g., sand 80) and chemicals 84, avoiding manual transport ofproppants and chemicals 84 to/from one or more well sites 10 and/or oneor more fracturing sites 52, sourcing/selecting of chemicals, blendingof proppants and/or chemicals, renting/owning pumps and control systemsfor chemical addition on location, and so forth. Costs are also savedbecause the friction-reducing additive 142 may be added via a low-shearaddition system 140 to form the friction-reduced hydraulic fracturingslurry 90, which is allowed to condition en route to one or more wellsites 10 and/or one or more fracturing sites 52 (e.g., via therelatively long pipes 136 described herein, in certain embodiments) atlow-shear—the gentle treatment of the friction-reduced hydraulicfracturing slurry 90 means the median molecular weight of thefriction-reducing additive 142 within the friction-reduced hydraulicfracturing slurry 90 is maintained to a greater extent than inrelatively high-shear mixers, improving polymer efficiency by as much as15%. Finally, in certain embodiments, costs are saved because thedensity of produced water 88 is higher than that of fresh water and,therefore, the contribution of the hydrostatic term (e.g., weight of thefriction-reduced hydraulic fracturing slurry 90) on net fracturingpressure is greater, thus allowing savings on diesel fuel to powerfracturing pumps 146 used to fracture the wells 22 and/or leading tocompletion of stages in shorter times.

The embodiments described herein offer well site operators theopportunity to purchase pre-formulated performative fracturing slurry 90from the same agency they are currently turning their produced water 88over to for treatment/disposal. However, the embodiments describedherein provide further specific advantages. For example, in certainembodiments, produced water 88 may be turned over to the centralizedfacility 66 and held there. Operators of the wells 22 may then contractwith the operators of the centralized facility 66 to “book” a volume ofready-to-use friction-reduced hydraulic fracturing slurry 90 based onupcoming completion activity for the wells 22. In response, thecentralized facility 66 may prepare the friction-reduced hydraulicfracturing slurry 90 just prior to release of the friction-reducedhydraulic fracturing slurry 90 when needed. This slurry-on-demand leavesthe centralized facility 66 and arrives at a well site 10 and/orfracturing site 52 as a performative fluid that, for example, may entera storage tank or a blender, as described herein, and then be pumpedinto a fracturing well 48 without necessity of any chemical additionson-site at the well site 10 and/or fracturing site 52, in certainembodiments.

Returning now to FIG. 13 , as described in greater detail herein,various other combinations of processing equipment 78 may be employed toensure that the friction-reduced hydraulic fracturing slurry 90 iscustomized for the specific needs of the one or more fracturing wells 48in which the friction-reduced hydraulic fracturing slurry 90 is used.For example, in certain embodiments, various combinations of processtrains may be employed to convey the friction-reduced hydraulicfracturing slurry 90 from the centralized facility 66 to the one or morewell sites 10 via the one or more fracturing slurry pipelines 74 (e.g.,which may include the relatively long pipes 136 described herein, incertain embodiments). For example, as illustrated in FIG. 13 , incertain embodiments, one or more transfer pumps 164 located at thecentralized facility 66 may be used to pump the friction-reducedhydraulic fracturing slurry 90 from the centralized facility 66 to theone or more well sites 10 and/or one or more fracturing sites 52 via theone or more fracturing slurry pipelines 74. In addition, in certainembodiments, one or more booster pumps 166 located along the one or morefracturing slurry pipelines 74 may be used to periodically boost thepressure of the friction-reduced hydraulic fracturing slurry 90 to allowthe pressure of the friction-reduced hydraulic fracturing slurry 90 toremain relatively low, as described in greater detail herein. Similarly,as also illustrated in FIG. 13 , in certain embodiments, one or moretransfer pumps 148 located at the one or more well sites 10 may be usedto pump produced water 88 from the one or more well sites 10 to thecentralized facility 66 via one or more produced water pipelines 70.

As described in greater detail herein, the transfer pumps 164 and thebooster pumps 166 that urge the fracturing slurry 90 (and other fluids,in certain embodiments) from the centralized facility 66 to the one ormore fracturing sites 52 maintain the pressure of the fracturing slurry90 (and the other fluids) at a relatively low range of approximately 0pounds per square inch (psi) to approximately 200 psi, in certainembodiments, as compared to the relatively high pressure ranges used infracturing operations at the fracturing sites 52 of approximately 1,000psi to approximately 10,000 psi. For example, in certain embodiments,the relatively low pressure that is used may be a maximum of less than400 psi, less than 350 psi, less than 300 psi, less than 250 psi, lessthan 200 psi, or even less.

Accordingly, relatively low pressure centrifugal pumps may be used asthe transfer pumps 164 and the booster pumps 166, and transfer hoses,temporary lay-flat hoses, high density polyethylene (HDPE) pipes (orother polymeric pipes), semi-permanent or permanent steel pipes, andother relatively low pressure conduits may be used as the one or morefracturing slurry pipelines 74 (e.g., which may include the relativelylong pipes 136 described herein). In general, the fracturing slurrypipelines 74 may include any suitable transfer lines robust enough toconvey water and solids. Similarly to the fracturing slurry pipelines74, the wet sand pipelines 72 described herein may also include anysuitable transfer lines robust enough to convey water and solids.

In addition, in certain embodiments, additional water (e.g.,non-friction-reduced water) may be added to adjust the composition ofthe friction-reduced hydraulic fracturing slurry 90. For example, incertain embodiments, additional water from other water sources (e.g.,such as those described herein) located at or near the centralizedfacility 66 may be added to the produced water 88 received from the oneor more well sites 10 to produce diluted produced water prior to addingthe friction-reducing additive 142 to the produced water 88 using thelow-shear addition system 140, and the friction-reducing additive 142may then be added to the diluted produced water to produce thefriction-reduced hydraulic fracturing slurry 90 using the low-shearaddition system 140. In addition, in certain embodiments, additionalwater from a water source located at the one or more fracturing sites 52may be added to the friction-reduced hydraulic fracturing slurry 90prior to injecting the friction-reduced hydraulic fracturing slurry 90into the one or more fracturing wells 48. In addition, in certainembodiments, additional water from a water source located at anintermediate location along the one or more fracturing slurry pipelines74 between the centralized facility 66 and the one or more fracturingsites 52 may be added to the friction-reduced hydraulic fracturingslurry 90 prior to delivering the friction-reduced hydraulic fracturingslurry 90 to the one or more fracturing sites 52. It will be appreciatedthat any combination of these water addition techniques may be employedin certain embodiments to adjust the composition of the friction-reducedhydraulic fracturing slurry 90. In addition, as described in greaterdetail herein, in certain embodiments, additional water, otheradditives, and other fluids, may be delivered from the centralizedfacility 66 to the one or more fracturing sites 52 concurrently, and maybe mixed together at the one or more fracturing sites 52 prior toinjecting the friction-reduced hydraulic fracturing slurry 90 into theone or more fracturing wells 48.

In addition, in certain embodiments, one or more other additives 168 maybe added to the friction-reduced hydraulic fracturing slurry 90 at thecentralized facility 66 prior to conveying the friction-reducedhydraulic fracturing slurry 90 to the one or more fracturing sites 52.In certain embodiments, the one or more additives 168 may include atleast one or a biocide, a flowback surfactant, an acid, a claystabilizer, a tracer, a scale inhibitor, an oxygen scavenger, a hydrogensulfide scavenger, a reducing agent, a chelant, an iron control agent,an anti-emulsion agent, a demulsifier, a breaker, a corrosion inhibitor,a pipeline cleaning agent, or a gel pig.

In addition, in certain embodiments, the friction-reduced hydraulicfracturing slurry 90 may be stored in storage facilities such as tanks,lined pits, and so forth. For example, as illustrated in FIG. 7 , incertain embodiments, the friction-reduced hydraulic fracturing slurry 90may be stored in storage (see, e.g., storage 92 in FIG. 6 ) located atthe centralized facility 66 prior to conveying the friction-reducedhydraulic fracturing slurry 90 to the one or more fracturing sites 52.In addition, in certain embodiments, the friction-reduced hydraulicfracturing slurry 90 may be stored in storage located at the one or morefracturing sites 52 after receiving the friction-reduced hydraulicfracturing slurry 90 from the centralized facility 66 and prior toinjecting the friction-reduced hydraulic fracturing slurry 90 into oneor more fracturing wells 48. Furthermore, in certain embodiments, thefriction-reduced hydraulic fracturing slurry 90 may be stored at anintermediate location along the one or more fracturing slurry pipelines74 (e.g., which may include the relatively long pipes 136 describedherein, in certain embodiments) between the centralized facility 66 andthe one or more fracturing sites 52. It will be appreciated that anycombination of these storage options may be employed in certainembodiments.

In addition, in certain embodiments, one or more additional chemicalsand/or proppants 170 may be added to the friction-reduced hydraulicfracturing slurry 90 prior to injecting the friction-reduced hydraulicfracturing slurry 90 into one or more fracturing wells 48. For example,in certain embodiments, the one or more chemicals and/or proppants 170may be added to the friction-reduced hydraulic fracturing slurry 90using one or more blenders located at the one or more fracturing sites52 prior to injecting the friction-reduced hydraulic fracturing slurry90 into one or more fracturing wells 48. However, in other embodiments,the one or more chemicals and/or proppants 170 may be added to thefriction-reduced hydraulic fracturing slurry 90 using one or moreblenders located at a site external to the one or more fracturing sites52 (e.g., including the centralized facility 66) prior to injecting thefriction-reduced hydraulic fracturing slurry 90 into one or morefracturing wells 48. It will be appreciated that the one or morechemicals and/or proppants 170 may include any of the other chemicalsand/or proppants described herein.

In addition, in certain embodiments, one or more process control systems94 may be used to control any and all operational parameters of thecentralized facility 66 and/or the one or more well sites 10 and/or theone or more fracturing sites 52 to facilitate the production anddelivery of friction-reduced hydraulic fracturing slurry 90 to one ormore fracturing wells 48 of the one or more fracturing sites 52, asdescribed in greater detail herein. Indeed, in certain embodiments, theone or more process control systems 94 may be used to automatically(e.g., without human intervention) adjust any and all operationalparameters of the centralized facility 66 and/or the one or more wellsites 10 and/or the one or more fracturing sites 52 to facilitate theproduction and delivery of friction-reduced hydraulic fracturing slurry90 to one or more fracturing wells 48 of the one or more fracturingsites 52, as described in greater detail herein.

For example, as illustrated in FIG. 7 , a process control system 94A maybe used to control operational parameters of the processing equipment 78located at the centralized facility 66 based at least in part onreal-time measurements collected by one or more sensors (see, e.g., thesensors 96 illustrated in FIG. 6 ) disposed about the centralizedfacility 66. In certain embodiments, the operational parameters of theprocessing equipment located at the centralized facility 66 that may becontrolled by the process control system 94A may include, but are notlimited to, a blending ratio between the sand 80, the chemicals 84, andthe produced water 88 by manipulating flow pumps and/or valves of thecentralized facility 66, flow rates and/or compositions of thefriction-reducing additive 142 and/or the fluid 144 into the low-shearaddition system 140 by manipulating flow pumps and/or valves of thecentralized facility 66, a blending ratio between the friction-reducingadditive 142 and the fluid 144 into the low-shear addition system 140 bymanipulating flow pumps and/or valves of the centralized facility 66,flow rates and/or compositions of the one or more additives 168 into thefriction-reduced hydraulic fracturing slurry 90 by manipulating valvesof the centralized facility 66, flow rates of the friction-reducedhydraulic fracturing slurry 90 to the one or more fracturing sites 52 bymanipulating transfer pumps 164, and so forth.

In certain embodiments, the real-time measurements that may be collectedby the one or more sensors (see, e.g., the sensors 96 illustrated inFIG. 6 ) disposed about the centralized facility 66 may include, but arenot limited to, water quality (e.g., pH, electrical conductivity, and soforth) of the water sources at the centralized facility 66 (e.g., of theproduced water 88 received from the one or more well sites 10, of otherwater sources, and so forth), specific gravity of the sand 80, thechemicals 84, the produced water 88, and/or the friction-reducedhydraulic fracturing slurry 90 produced by the centralized facility 66,turbidity of the sand 80, the chemicals 84, the produced water 88,and/or the friction-reduced hydraulic fracturing slurry 90 produced bythe centralized facility 66, compositions of the sand 80, the chemicals84, the produced water 88, and/or the friction-reduced hydraulicfracturing slurry 90 produced by the centralized facility 66, frictionreduction of the friction-reduced hydraulic fracturing slurry 90produced by the centralized facility 66 as compared to the water (e.g.,the produced water 88 received from one or more well sites 10 and/oradditional water from a water source at the centralized facility 66),and so forth.

In addition, as also illustrated in FIG. 7 , one or more process controlsystems 94B may be used to control operational parameters of processingequipment located at the one or more fracturing sites 52 and/or the oneor more well sites 10 based at least in part on real-time measurementscollected by one or more sensors disposed about the one or morefracturing sites 52 and/or the one or more well sites 10. As will beappreciated, in embodiments where the well sites 10 are also fracturingsites 52, only one process control system 94B may be used.

In certain embodiments, the operational parameters of the processingequipment located at the one or more fracturing sites 52 and/or the oneor more well sites 10 that may be controlled by the process controlsystem 94B may include, but are not limited to, flow rates of thefriction-reduced hydraulic fracturing slurry 90 delivered to the one ormore fracturing sites 52 by manipulating flow pumps and/or valves of theone or more fracturing sites 52, flow rates and/or compositions of theone or more additional chemicals/proppants 170 into one or more blendersby manipulating valves to control the blending of the one or moreproppants 170 and the friction-reduced hydraulic fracturing slurry 90performed by the one or more blenders, flow rates of additional waterinto the friction-reduced hydraulic fracturing slurry 90 by manipulatingvalves of the one or more fracturing sites 52, flow rates of thefriction-reduced hydraulic fracturing slurry 90 injected into the one ormore fracturing wells 48 by manipulating one or more fracturing pumps146 and/or valves of the one or more fracturing sites 52, flow rates ofproduced water 88 from the one or more well sites 10 to the centralizedfacility 66 by manipulating transfer pumps 148A of the one or more wellsites 10, and so forth.

In certain embodiments, the real-time measurements that may be collectedby the one or more sensors disposed about the one or more fracturingsites 52 and/or the one or more well sites 10 may include, but are notlimited to, formation treating pressure and other operational parametersof one or more wells 22 at the one or more well sites 10, water quality(e.g., pH, electrical conductivity, and so forth) at the one or morewell sites 10 (e.g., of the produced water 88), specific gravity of thefriction-reduced hydraulic fracturing slurry 90, turbidity of thefriction-reduced hydraulic fracturing slurry 90, compositions of thefriction-reduced hydraulic fracturing slurry 90, and so forth.

In addition, in certain embodiments, the process control systems 94A,94B may cooperate with each other such that operational parameters ofthe processing equipment located at the one or more fracturing sites 52and/or the one or more well sites 10 may be collectively controlled bythe process control systems 94A, 94B based at least in part on real-timemeasurements collected by one or more sensors (see, e.g., the sensors 96illustrated in FIG. 6 ) disposed about the centralized facility 66and/or operational parameters of the processing equipment 78 located atthe centralized facility 66 may be collectively controlled by theprocess control systems 94A, 94B based at least in part on real-timemeasurements collected by one or more sensors disposed about the one ormore fracturing sites 52 and/or the one or more well sites 10. Inaddition, it will be appreciated that other operational parameters ofthe processing equipment 78 located at the centralized facility 66and/or the one or more fracturing sites 52 and/or the one or more wellsites 10 may be controlled by the process control system 94A and/or theprocess control system 94B based at least in part on other real-timemeasurements collected by one or more sensors (see, e.g., the sensors 96illustrated in FIG. 6 ) disposed about the centralized facility 66and/or the one or more fracturing sites 52 and/or the one or more wellsites 10. Indeed, any and all operational parameters of the processingequipment located at the centralized facility 66 and/or the one or morefracturing sites 52 and/or the one or more well sites 10 may becontrolled by the process control system 94A and/or the process controlsystem 94B based at least in part on any and all real-time measurementscollected by one or more sensors (see, e.g., the sensors 96 illustratedin FIG. 6 ) disposed about the centralized facility 66 and/or the one ormore fracturing sites 52 and/or the one or more well sites 10.

As illustrated in FIG. 16 , in certain embodiments, the process controlsystems 94 described herein may each (or, alternatively, collectively)include one or more process control modules 172 (e.g., a program ofcomputer-executable instructions and associated data) that may beconfigured to perform various functions of the embodiments describedherein. In certain embodiments, to perform these various functions, aprocess control module 172 executes on one or more processors 174 of theprocess control system(s) 94, which may be connected to one or morestorage media 176 of the process control system(s) 94. Indeed, incertain embodiments, the one or more process control modules 172 may bestored in the one or more storage media 176.

In certain embodiments, the one or more processors 174 may include amicroprocessor, a microcontroller, a processor module or subsystem, aprogrammable integrated circuit, a programmable gate array, a digitalsignal processor (DSP), or another control or computing device. Incertain embodiments, the one or more storage media 176 may beimplemented as one or more non-transitory computer-readable ormachine-readable storage media. In certain embodiments, the one or morestorage media 176 may include one or more different forms of memoryincluding semiconductor memory devices such as dynamic or static randomaccess memories (DRAMs or SRAMs), erasable and programmable read-onlymemories (EPROMs), electrically erasable and programmable read-onlymemories (EEPROMs) and flash memories; magnetic disks such as fixed,floppy and removable disks; other magnetic media including tape; opticalmedia such as compact disks (CDs) or digital video disks (DVDs); orother types of storage devices. Note that the computer-executableinstructions and associated data of the process control module(s) 172may be provided on one computer-readable or machine-readable storagemedium of the storage media 176, or alternatively, may be provided onmultiple computer-readable or machine-readable storage media distributedin a large system having possibly plural nodes. Such computer-readableor machine-readable storage medium or media are considered to be part ofan article (or article of manufacture), which may refer to anymanufactured single component or multiple components. In certainembodiments, the one or more storage media 176 may be located either inthe machine running the machine-readable instructions, or may be locatedat a remote site from which machine-readable instructions may bedownloaded over a network for execution.

In certain embodiments, the processor(s) 174 may be connected tocommunication circuitry 178 of the process control system(s) 94 to allowthe process control system(s) 94 to communicate with the varioussensors, the various processing equipment of the centralized facility 66and/or the one or more fracturing sites 52 and/or the one or more wellsites 10 (as well as other systems described herein), and so forth, forthe purpose of controlling operation of the systems described in greaterdetail herein. In certain embodiments, the communication circuitry 178may also facilitate the process control system(s) 94 to communicate datato cloud storage 180 (or other wired and/or wireless communicationnetwork) to, for example, archive the data or to enable externalcomputing systems 182 to access the data and/or to remotely interactwith the process control system(s) 94.

In certain embodiments, the communication circuitry 178 may be, include,or be implemented by various types of standard interfaces, such as anEthernet interface, a universal serial bus (USB), a third generationinput/output (3GIO) interface, a wireless interface, a cellularinterface, and/or a satellite interface, among others. In certainembodiments, the communication circuitry 178 may also include acommunication device, such as a modem or network interface card tofacilitate exchange of data with external computing devices via anetwork (e.g., Ethernet connection, digital subscriber line (DSL),telephone line, coaxial cable, cellular telephone system, satellite,etc.).

In certain embodiments, friction-reduced hydraulic fracturing slurry,additional water, one or more additives 168, and other fluids may beconveyed from the centralized facility 66 to the one or more fracturingsites 52 concurrently via the one or more fracturing slurry pipelines74. For example, in certain embodiments, the one or more fracturingslurry pipelines 74 may include multiple pipelines 74 disposed inparallel with each other, each of the pipelines 74 conveying a differentfluid.

As illustrated in FIG. 17 , in certain embodiments, a single pipeline74A may include an external pipe 184 with an internal pipe 186 disposedconcentrically within the external pipe 184. As such, an interior of theinternal pipe 186 forms an internal volume 188 and the annular spacebetween the external pipe 184 and the internal pipe 186 forms anexternal volume 190. In such an embodiment, a first fluid may beconveyed from the centralized facility 66 to the one or more fracturingsites 52 through the internal volume 188 of the pipeline 74Aconcurrently with a second fluid conveyed from the centralized facility66 to the one or more fracturing sites 52 through the external volume190 of the pipeline 74A. For example, in certain embodiments, thefriction-reduced hydraulic fracturing slurry 90 may be conveyed from thecentralized facility 66 to the one or more fracturing sites 52 throughthe internal volume 188 of the pipeline 74A concurrently with additionalwater (e.g., non-friction-reduced water) conveyed from the centralizedfacility 66 to the one or more fracturing sites 52 through the externalvolume 190 of the pipeline 74A. In other embodiments, additional water(e.g., non-friction-reduced water) may be conveyed from the centralizedfacility 66 to the one or more fracturing sites 52 through the internalvolume 188 of the pipeline 74A concurrently with the friction-reducedhydraulic fracturing slurry 90 conveyed from the centralized facility 66to the one or more fracturing sites 52 through the external volume 190of the pipeline 74A. Indeed, any and all combinations offriction-reduced hydraulic fracturing slurry 90, additional water, oneor more additives 168, and other fluids may be conveyed from thecentralized facility 66 to the one or more fracturing sites 52 throughthe various volumes 188, 190 of the pipeline 74A illustrated in FIG. 17.

As illustrated in FIG. 18 , in other embodiments, a single pipeline 74Bmay include an external pipe 184 and a plurality of internal pipes 186A,186B disposed within the external pipe 184. As such, interiors of eachof the internal pipes 186A, 186B form respective internal volumes 188A,188B and the annular space between the external pipe 184 and theinternal pipes 186A, 186B forms an external volume 190. In such anembodiment, a first fluid may be conveyed from the centralized facility66 to the one or more fracturing sites 52 through a first internalvolume 188A of the pipeline 74B concurrently with a second fluidconveyed from the centralized facility 66 to the one or more fracturingsites 52 through a second internal volume 188B of the pipeline 74Bconcurrently with a third fluid conveyed from the centralized facility66 to the one or more fracturing sites 52 through the external volume190 of the pipeline 74B. In particular, any and all combinations offriction-reduced hydraulic fracturing slurry 90, additional water, oneor more additives 168, and other fluids may be conveyed from thecentralized facility 66 to the one or more fracturing sites 52 throughthe various volumes 188, 190 of the pipeline 74B illustrated in FIG. 18. Although illustrated in FIG. 18 as including two internal pipes 186A,186B, in other embodiments, the pipeline 74B may include any number(e.g., two, three, four, five, or even more) of internal pipes 186.

In certain embodiments, the various volumes 188, 190 of the pipelines74A, 74B illustrated in FIGS. 17 and 18 may be used to facilitatemulti-directional flow of fluids through the volumes 188, 190. Forexample, although in certain embodiments, certain fluids may flow in aunidirectional manner from the centralized facility 66 to one or morefracturing sites 52 within respective volumes 188, 190 of the pipelines74A, 74B, in other embodiments, a first fluid may flow from thecentralized facility 66 to one or more fracturing sites 52 through oneof the volumes 188, 190 while a second fluid may flow in the oppositedirection from the one or more fracturing sites 52 to the centralizedfacility 66 in another of the volumes 188, 190. As but one non-limitingexample, in an embodiment where a fracturing site 52 is also aproduction well site 10, produced water 88 from the fracturing site 52may be conveyed to the centralized facility 66 through one of thevolumes 188, 190 of a pipeline 74A, 74B whereas fracturing slurry 90 maybe conveyed from the centralized facility 66 to the fracturing site 52via another of the volumes 188, 190 of the pipeline 74, 74B.

Returning now to FIGS. 6, 13, and 16 , as described in greater detailherein, the one or more process control systems 94 may be configured tocontrol any and all operating parameters of the centralized facility 66and/or the one or more well sites 10 and/or the one or more fracturingsites 52. For example, in certain embodiments, the one or more processcontrol systems 94 may be configured to control flow rates of theplurality of fluids conveyed by the pipelines 74 illustrated in FIGS. 17and 18 such that blending ratios between the fluids conveyed therein areadjusted to achieve a desired end state or final concentration at theone or more fracturing sites 52 to achieve optimal friction reductionfor the particular operating conditions of the one or more fracturingwells 48 at the one or more fracturing sites 52 (e.g., determined by theone or more process control systems 94 based on real-time measurementscollected by sensors at the centralized facility 66 and/or the one ormore fracturing sites 52 and/or the one or more well sites 10). Forexample, in certain embodiments, the one or more process control systems94 may be configured to manipulate valves associated with the respectivevolumes 188, 190 of the pipelines 74 to achieve appropriate blendingratios between the fluids conveyed by the volumes 188, 190 in order toproduce a final friction-reduced hydraulic fracturing slurry 90 based onthe particular operating conditions of the one or more fracturing wells48 at the one or more fracturing sites 52.

Similarly, in certain embodiments, the one or more process controlsystems 94 may be configured to select a particular friction-reducingadditive 142 (e.g., from a plurality of friction-reducing additives 142)for addition to the water at the low-shear addition system 140 at thecentralized facility 66 in order to produce a friction-reduced hydraulicfracturing slurry 90 based on the particular operating conditions of theone or more fracturing wells 48 at the one or more fracturing sites 52.For example, in certain embodiments, the one or more process controlsystems 94 may analyze the compositions of the fluid 144 to which thefriction-reduced additive 142 is to be added and, based on theparticular operating conditions of the one or more fracturing wells 48at the one or more fracturing sites 52, may determine that a particularfriction-reducing additive 142 (e.g., from a plurality offriction-reducing additives 142) and/or a particular concentration ofthe friction-reducing additive 142 may be ideal to convert the fluid 144into a friction-reduced hydraulic fracturing slurry 90 that will meetthe particular operating conditions of the one or more fracturing wells48 at the one or more fracturing sites 52. Furthermore, in certainembodiments, the selection of the particular friction-reducing additive142 (e.g., from a plurality of friction-reducing additives 142) and/or aparticular concentration of the friction-reducing additive 142 may bedetermined by the one or more process control systems 94 based at leastin part on performance parameters of the one or more wells 22 at the oneor more well sites 10, for example, which may be derived by the one ormore process control systems 94 from archived performance measurementsof the one or more wells 22 (e.g., archived in the cloud storage 180).

The specific embodiments described above have been illustrated by way ofexample, and it should be understood that these embodiments may besusceptible to various modifications and alternative forms. It should befurther understood that the claims are not intended to be limited to theparticular forms disclosed, but rather to cover all modifications,equivalents, and alternatives falling within the spirit and scope ofthis disclosure.

1. A method, comprising: receiving water at a centralized facility;receiving sand from one or more sand mines at the centralized facility;receiving one or more chemicals at the centralized facility; usingprocessing equipment of the centralized facility to process the water,the sand, and the one or more chemicals to produce a fracturing slurry,wherein using the processing equipment comprises: using a dilutionmanifold to dilute concentrations of the sand, the one or morechemicals, or both, in the fracturing slurry; using dewatering equipmentto remove water from the fracturing slurry; using blending equipment toadd water into the fracturing slurry; or using a low-shear additionsystem to add a friction-reducing additive to the fracturing slurry; ora combination thereof; and conveying the fracturing slurry from thecentralized facility to one or more fracturing sites.
 2. The method ofclaim 1, comprising conveying the fracturing slurry from the centralizedfacility to the one or more fracturing sites using one or morefracturing slurry pipelines.
 3. The method of claim 2, wherein the oneor more fracturing slurry pipelines comprise one or more transfer hoses,one or more temporary lay-flat hoses, one or more polymeric pipes, orsome combination thereof.
 4. The method of claim 2, comprising boostinga pressure of the fracturing slurry at one or more intermediatelocations along the one or more fracturing slurry pipelines.
 5. Themethod of claim 1, comprising using a process control system toautomatically adjust one or more properties of the fracturing slurrybased at least in part on one or more operating parameters relating tothe water, the sand, or the one or more chemicals, or a combinationthereof.
 6. The method of claim 1, wherein the one or more sand minescomprise one or more mobile sand mines.
 7. The method of claim 1,comprising: conveying the water from the centralized facility to the oneor more sand mines; and using the water in mining operations at the oneor more sand mines.
 8. The method of claim 1, comprising passivelymixing the water, the sand, and the one or more chemicals without usingactive mixing equipment.
 9. The method of claim 1, wherein: using theprocessing equipment of the centralized facility to process the water,the sand, and the one or more chemicals comprises using the low-shearaddition system to add the friction-reducing additive to the fracturingslurry; and using the low-shear addition system to add thefriction-reducing additive to the fracturing slurry comprises using atleast one eductor to disperse the friction-reducing additive into thefracturing slurry.
 10. A method, comprising: receiving water at acentralized facility via one or more water pipelines; receiving sandfrom one or more sand mines at the centralized facility via one or moresand pipelines; receiving one or more chemicals at the centralizedfacility; using processing equipment of the centralized facility toprocess the water, the sand, and the one or more chemicals to produce afracturing slurry, wherein using the processing equipment comprises:using a dilution manifold to dilute concentrations of the sand, the oneor more chemicals, or both, in the fracturing slurry; using dewateringequipment to remove water from the fracturing slurry; using blendingequipment to add water into the fracturing slurry; or using a low-shearaddition system to add a friction-reducing additive to the fracturingslurry; or a combination thereof; and conveying the fracturing slurryfrom the centralized facility to one or more fracturing sites via one ormore fracturing slurry pipelines.
 11. The method of claim 10, comprisingboosting a pressure of the fracturing slurry at one or more intermediatelocations along the one or more fracturing slurry pipelines.
 12. Themethod of claim 10, comprising passively mixing the water, the sand, andthe one or more chemicals without using active mixing equipment.
 13. Themethod of claim 10, comprising using a process control system toautomatically adjust one or more properties of the fracturing slurrybased at least in part on one or more operating parameters relating tothe water, the sand, or the one or more chemicals, or a combinationthereof.
 14. The method of claim 10, comprising: conveying the waterfrom the centralized facility to the one or more sand mines; and usingthe water in mining operations at the one or more sand mines.
 15. Themethod of claim 10, wherein the water is produced water from one or morewell sites.
 16. The method of claim 10, wherein the one or morefracturing slurry pipelines comprise a textured, interior surface thatfacilitates passive mixing of the fracturing slurry.
 17. A method,comprising: receiving produced water from one or more well sites at acentralized facility via one or produced water pipelines; receiving sandfrom one or more sand mines at the centralized facility via one or moresand pipelines; receiving one or more chemicals at the centralizedfacility; and conveying the produced water, the sand, and the chemicalsfrom the centralized facility to one or more fracturing sites via one ormore fracturing slurry pipelines and processing equipment of thecentralized facility, wherein: movement of the produced water, the sand,and the one or more chemicals through the one or more fracturing slurrypipelines and the processing equipment passively mixes the producedwater, the sand, and the one or more chemicals into a fracturing slurrywithout using active mixing equipment; and the processing equipmentcomprises: a dilution manifold to dilute concentrations of the sand, theone or more chemicals, or both, in the fracturing slurry; dewateringequipment to remove produced water from the fracturing slurry; blendingequipment to add produced water into the fracturing slurry; or alow-shear addition system to add a friction-reducing additive to thefracturing slurry; or a combination thereof.
 18. The method of claim 17,comprising boosting a pressure of the fracturing slurry at one or moreintermediate locations along the one or more fracturing slurrypipelines.
 19. The method of claim 17, comprising using a processcontrol system to automatically adjust one or more properties of thefracturing slurry based at least in part on one or more operatingparameters relating to the produced water, the sand, or the one or morechemicals, or a combination thereof.
 20. The method of claim 17,comprising: conveying the produced water from the centralized facilityto the one or more sand mines; and using the produced water in miningoperations at the one or more sand mines.